This invention relates to a method of placing material in an earth formation penetrated by a well bore and, more particularly, to the pneumatic transfer of particulate solid materials into an earth formation penetrated by a well bore.
There are many techniques known in the art for placing material in an earth formation penetrated by a well bore.
Certain of the prior techniques involve the placement of lost circulation materials in a highly porous zone when drilling a well. The porous zone may be taking drilling fluid in such amounts that none remains for circulation of the hole, for instance. Similarly, in water injection wells one highly porous interval of a formation may be taking all or substantially all of the injected water, thereby preventing good water flood results over the entire producing formation. The same problem develops in producing wells where an unconsolidated formation causes sand to be deposited in a producing well. In such cases, it is often desirable to place sand, gravel or a similar solid particulate material in a formation adjacent a well liner to overcome such problems.
Other prior techniques for placing particulate material in well bores involve well stimulation. In stimulating production of crude oil and natural gas from wells drilled in reservoirs of low permeability, the earthern formation is typically fractured with various liquids, such as crude oil, with or without propping agents, such as sand suspended therein. The hydraulic pressure applied to such formations creates stresses in the rock of the formation surrounding the well bore and causes splitting or fracturing of the rock. The initially formed fractures or channels are then extended by the injection of fluids containing propping agents to be deposited in the fractures. When the pressure is released, the propping agent deposited in the fractures holds the fractures open, leaving channels for reservoir fluid flow. The concentration of propping agent in the fracture is significant since it determines the final thickness of the fracture.
A more recent development in fracturing techniques involves the use of a fracturing foam which is formed by blending sand into gelled water and treating the slurry with a surfactant. The fluid pressure is increased with a pump after which a gas, such as nitrogen or carbon dioxide, is injected into the fluid to create a high pressure foam. Foam has several advantages over traditional fluids, such as low fluid loss and decreased formation damage for water sensitive formations. Sand does not settle out of the foam quickly during unplanned shutdowns during the treatment and foam has a high effective viscosity.
An even more recent development in well fracturing is the use of gaseous nitrogen alone as a fracturing fluid. There are several advantages of using nitrogen as the fracturing fluid, including its non-damaging characteristics, minimum shut-in time and nominal treatment costs. The liquid content of fracturing fluids is extremely crucial when treating liquid sensitive formations since liquids can cause clay migration and swelling in the formation, thereby reducing permeability to the produced fluids. Nitrogen, on the other hand, is inert, relatively insoluble and compressible. These properties minimize damage to shale formations, in particular. Nitrogen fracturing also virtually eliminates the cleanup problems associated with liquid systems. Once the treatment is completed, the well is opened up and the gas is flowed back. Production is not lost and costly swabbing units to recover fluids are not needed.
Even though nitrogen fracturing has many advantages over traditional liquid and foam fracturing techniques, the need exists for a nitrogen fracturing technique which allows the simultaneous placement of propping agents within the fractured earthern formation. The propping agent is then effective to prop open the crevices created and withstand the tremendous pressures from the overburden when the fracturing pressure is relieved.